MX2010008132A - Detection and automatic correction for deposition in a tubular using multi-energy gamma-ray measurements. - Google Patents
Detection and automatic correction for deposition in a tubular using multi-energy gamma-ray measurements.Info
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- MX2010008132A MX2010008132A MX2010008132A MX2010008132A MX2010008132A MX 2010008132 A MX2010008132 A MX 2010008132A MX 2010008132 A MX2010008132 A MX 2010008132A MX 2010008132 A MX2010008132 A MX 2010008132A MX 2010008132 A MX2010008132 A MX 2010008132A
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N33/00—Investigating or analysing materials by specific methods not covered by groups G01N1/00 - G01N31/00
- G01N33/26—Oils; viscous liquids; paints; inks
- G01N33/28—Oils, i.e. hydrocarbon liquids
- G01N33/2823—Oils, i.e. hydrocarbon liquids raw oil, drilling fluid or polyphasic mixtures
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N23/00—Investigating or analysing materials by the use of wave or particle radiation, e.g. X-rays or neutrons, not covered by groups G01N3/00 – G01N17/00, G01N21/00 or G01N22/00
- G01N23/02—Investigating or analysing materials by the use of wave or particle radiation, e.g. X-rays or neutrons, not covered by groups G01N3/00 – G01N17/00, G01N21/00 or G01N22/00 by transmitting the radiation through the material
- G01N23/06—Investigating or analysing materials by the use of wave or particle radiation, e.g. X-rays or neutrons, not covered by groups G01N3/00 – G01N17/00, G01N21/00 or G01N22/00 by transmitting the radiation through the material and measuring the absorption
- G01N23/083—Investigating or analysing materials by the use of wave or particle radiation, e.g. X-rays or neutrons, not covered by groups G01N3/00 – G01N17/00, G01N21/00 or G01N22/00 by transmitting the radiation through the material and measuring the absorption the radiation being X-rays
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N23/00—Investigating or analysing materials by the use of wave or particle radiation, e.g. X-rays or neutrons, not covered by groups G01N3/00 – G01N17/00, G01N21/00 or G01N22/00
- G01N23/02—Investigating or analysing materials by the use of wave or particle radiation, e.g. X-rays or neutrons, not covered by groups G01N3/00 – G01N17/00, G01N21/00 or G01N22/00 by transmitting the radiation through the material
- G01N23/06—Investigating or analysing materials by the use of wave or particle radiation, e.g. X-rays or neutrons, not covered by groups G01N3/00 – G01N17/00, G01N21/00 or G01N22/00 by transmitting the radiation through the material and measuring the absorption
- G01N23/12—Investigating or analysing materials by the use of wave or particle radiation, e.g. X-rays or neutrons, not covered by groups G01N3/00 – G01N17/00, G01N21/00 or G01N22/00 by transmitting the radiation through the material and measuring the absorption the material being a flowing fluid or a flowing granular solid
Abstract
A method to detect deposits (109) in a tubular (101) in which a fluid is flowing is disclosed. The method comprises measuring the water-liquid- ratio of the fluid as a function of time and determining that a deposit exists if the measured water-liquid- ratio of the fluid as a function of time is linear.
Description
DETECTION AND AUTOMATIC CORRECTION FOR DEPOSITION IN A
TUBULAR STRUCTURE USING GAMMA RAY MEASUREMENTS
MULTIENERGÍA BACKGROUND
Field of the Invention
The description generally relates to a method for detecting a deposit in a tubular structure, and particularly to a method for detecting a deposit in a tubular structure using multi-energy gamma-ray measurements.
Background Art
During the production from an oil well, the formation of precipitates and / or deposits in the tubular structures through which the fluids flow, causing interruption of production and intervention work, may occur. The precipitates and / or deposits may be asphaltenes, wax, scale, etcetera. The deposition in the inner diameter of a tubular structure, such as the pipe strings, can occur as a result of changes in temperature and pressure, or after evaporation of the water from the fluid or changes in the pH value of the fluid.
Deposits and / or precipitates affect fluid production and transport in a pipeline. This is the result,
for example, a decrease in the productivity of the oilfield, a higher uncertainty in the production and in the monitoring data of the deposit, and an increased production cost due to the frequent treatments required for the prevention and removal of the deposit. In particular, the presence of these precipitates and deposits alters the performance of the flow rate measuring devices, for example, for the allocation of production in reservoir administration applications.
To avoid these problems or to decrease the effect of the deposit, upstream heating devices can be installed, inhibitors can be injected into the pipe, or a scraper device can be inserted into the line.
A method for detecting and identifying a specific type of deposit (embedding) is described in WO 2003/04267. It is described from a theoretical point of view how a correction could be made if the incrustation was deposited inside a pipe. This solution, however, does not provide any detection and is based on the great contrast for the specific inlay. Accordingly, it is difficult to apply this method to other types of deposit materials, and in particular, to any type of deposit material.
Another example of a typical deposit is sand. The
Sand particles in the fluid, such as a mixture of crude oil, can be detected using multi-energy gamma or X-ray measurements. EP 236623 discloses measurements by attenuation of photons in more than two energy levels to obtain the mass flow rates of oil, water, gas, and sand. However, it does not provide a method for determining the thickness and composition of any type of deposit on the inner wall of the pipe.
A method that identifies the existence and composition of the deposits within the pipeline and that measures their thickness as well as the evolution of the deposit thickness over time would be highly desirable. Knowing the thickness of the reservoir that reduces the effective diameter of the tubing, it may then be possible to compensate for the error that is associated with the reservoir when making measurements of the multiphase flow rate. It may also be possible to obtain a better production allocation per well.
BRIEF DESCRIPTION OF THE INVENTION
In one aspect, the embodiments described herein relate to a method for detecting a reservoir in a tubular structure in which a fluid flows. The method involves measuring the water-liquid ratio of the fluid versus time and determining whether the water-liquid ratio is a linear function
of time, in which case there is a deposit.
Other aspects, features, and advantages of the invention will be apparent from the following detailed description and the appended claims.
BRIEF DESCRIPTION OF THE DRAWINGS
Figures la and Ib are schematic representations of an apparatus for detecting a deposit in a tubular structure according to the modalities described herein, installed a) a straight pipe and b) a neck section of a venturi.
Figures 2a and 2b are schematic representations. of an empty pipe with an apparatus according to the embodiments described herein, wherein in Figure 2a no deposit is present in the pipe, and in Figure 2b the deposits are present in the pipe.
Figure 3 is a graph representing the relationship between the mass attenuation coefficients of a reservoir for higher and lower gamma ray energies.
Figure 4 is a graph that represents the relationship between the proportions of the attenuation coefficients of a deposit.
DETAILED DESCRIPTION OF THE INVENTION
The specific embodiments of the present disclosure will now be described in detail with reference to the accompanying Figures. Similar elements in the various Figures
they can be denoted by similar reference numbers for consistency.
The embodiments described herein provide a method for detecting a deposit in an inner wall of a tubular structure, determining its thickness, and identifying the material of the deposit. The tubular structure may be any kind of conduit that carries fluid, such as a pipe, a production pipe, surface installations, or a venturi flow meter. In addition, as will be appreciated by the skilled person, the methods according to the present disclosure may be applicable whenever fluids flow in a tubular structure, giving rise to any kind of deposition, such that the applicability of the methods should not be restricted to the oilfield. .
The Applicant has shown that a specific relationship can be established between the temporal variation of the water-to-liquid ratio (WLR) of the fluid flowing in the tubular structure and the existence of deposit in the tubular structure. The WLR of a multiphase fluid can indicate the proportion of water with respect to the proportion of water and oil together. The methods for detecting the presence of a deposit in a tubular structure and measuring its thickness according to the modalities described herein can be based on this relationship.
The relationship between the temporal variation of the WLR and the presence of a deposit will now be derived in detail. Referring to Figure la, a tubular structure 101 is shown where a system 103, 105 is installed which measures the attenuation of the linear mass of the X-ray or gamma radiation by a fluid flowing in the tubular structure 101. A source 103 radiation attached to one side of the tubular structure 101 emits, for example, gamma radiation that propagates through the fluid and is detected by a detector 105 located on the opposite side of the tubular structure 101. Figure Ib shows a similar configuration , wherein the tubular structure 101 has a venturi section 107, which illustrates the configuration in a venturi flow meter,
The power or counting speed of the source 103 can be measured in a reference measurement where the tubular structure 101 is empty or filled with a known fluid 113 (for example air). The known fluid 113, indicated by the subscript "k", can be characterized by its mass attenuation coefficient vk (x) for a given radiation energy Ex and its density *. The counting speed of the reference measurement is as follows:
where { x) is the counting speed in detector 105, and N0. { x) is the counting speed in the radiation source 103. In the case of Figure la, d is the diameter Illa of the tubular structure 101.
As it is a multiphase fluid and to determine the fractions a (i - g, w, o) of the components of the multiphase fluid (ie, gas, water, and oil), it may be convenient to measure the counting rates in at least Two Ex and Ey levels of radiation energy:
where the condition is met
a, = 1 (2b)
If a deposit is in the tubular structure, the counting speed can be expressed as
N (x, t) = N0 (x) exp [- dT (a, (/), v, (x)) - dau (t) puvu (x)]
(3) where the subscript u indicates the unknown deposit, au [t) is the deposition rate dependent on time.
It can be assumed then that within a certain period
of time, ?? = t¿ - ti, fractions of oil phases,
water and gas do not vary significantly compared to the
fraction of the unknown component. The value of át depends on
the characteristics of the deposit material in the fluid and
of fluid characteristics (ie, the speed of
flow, temperature, and pressure). In this way, it is
possible to calculate the proportion of counting speeds
measurements in times ti and t¿:
- In2 y = -dpuv (*) (< ¾ "(t {) - au (t2)) < 4 )
The second term on the left side takes into account the
decay of the source between the first and the second
measurement, where T is the average life time of the source.
In addition, in most cases, it can be assumed that At / T
«1, so that this term disappears and (4) becomes:
If, in a first case, it is assumed that the speed
deposition u. { t) evolves linearly with time,
Equation (3) can be rewritten using equation (5)
N (x, t) = N. (x) exp [- d? (AlP! V, (x)) - Bt] (6)
where
where B is defined in the time interval At which is
negligible the variation of oil fractions,
water, and gas, to ±.
In a second case, it can be assumed that the speed of
deposition is an arbitrary function of time, such as
u (t) = atb, with a and b being real numbers. So, the
Equation (6) can be rewritten as follows:
N (x, t) = N0 (x) exp [-d? (AiPiv¡ (*)) -B. { x) tb] (8)
where B can be approximated by a series of Taylor's first
order around tj,
t-t and e is an arbitrarily small positive quantity, e =
B can be defined by a time interval ñt that is sufficiently short so that the temporal variation of the
Deposition velocity can be assumed as linear, as in
the first case. Therefore, it is possible to rewrite equation (8) in a general form under the hypothesis that e «1 as follows:
Equation (10) no longer depends on b so that it can be equivalent to equation (6), where b = 1.
In the case when there is no deposition in the pipeline, the fractions of the three oil, water, and gas phases can be calculated by solving the coupled equations (2a, 2b). If a total sum is carried out, the system (2a) of equations can be rewritten in a specific way,
N (x)
Iln + .p "vg (x) = -a0p0v" (x) -awpwv x),
? «, =! |
I
The system (11) of equations can be understood as a system comprising two unknowns, the oil and water fractions. The term of the gas on the left side can be very small compared to the terms of oil and water. It can compensate for the presence of gas in the measured counting speed (that is, the system (11) of
equations can be applied to a fluid that contains gas as well as to a fluid that does not contain gas). For the purpose of checking and to simplify notations, fractions aD and aw of oil and water can be expressed as
A0 (x) Av y) - A0. { y) Aw. { x) (12) with
In the case when there is deposition in the pipeline, the expression (14) for C (y) can be corrected using equation (10), as long as e «1:
Equation (12) can then be rewritten for the case of deposition that occurs in the pipeline so that it reads:
(16)
This leads to the following relationship between the evolution of oil and water fractions in the case of deposition and the fractions of oil and water in the case of no deposition:
where P0rW can be defined according to equation (16). The fractions of oil and water a ^ p (t) can thus vary linearly with time when deposition occurs in the pipeline.
The aforementioned WLR can be expressed as
a a
WLR = w
(18)
We can then assume that the multiphase fluid flowing in the pipe consists only of oil and water, a ^ ep (t) + a ^ ep = 1 (ie, no gas is present in the fluid flowing in the pipe). If a deposition occurs, a time-dependent WLRdep (t) can be written as
= rWxrLrRr > -Pr »(19)
A person having ordinary skill in the art will appreciate that even if gas is present in the fluid, the variation of the gas fraction ag due to a deposition
It can be very small. This does not significantly affect the calculation of the WLR because the absorption of the radiation in the gas fraction of the fluid is negligible. The variation of the WLR due to a deposit may be due mainly to the variations of the oil fractions and water of the fluid. Therefore, starting from equation (18), the time-dependent WLR when a deposition occurs can be generally written as
Expressions (12) - (19) can be more complex if the simplification of equation (11) is not done (that is, if the three components of the oil, water, and gas fluid are also considered). However, a solution similar to (19) will be obtained. If a deposition occurs, the WLRde (t) varies linearly with time. Accordingly, it is shown that it is possible to determine the presence of deposit in the tubular structure by measuring the WLR (or the oil and water fractions) over a period of time to establish the dependence of the WLR (or of the oil fractions and of water) of time.
If the thickness of the deposit is much smaller than the diameter of the tubular structure, the pressure can be measured
differential (ie, pressure drop). One method to determine the differential pressure is to measure the pressure of the fluid at two different locations in the tubular structure to obtain the DPI lost by natural pressure, as shown in Figure la. Another method is to use a V-cone or a venturi (as shown in Figure Ib), or any other device to measure the pressure drop, to obtain the differential pressure DPI or DP2. This pressure drop can be related to the total mass or volumetric flow velocity passing through the pipe. As will be appreciated by persons skilled in the art, any suitable multiphase flow measuring device can be used to measure the flow velocity. The Applicant has shown that if there is a constant volumetric flow rate during a given period of time, and during this period a linear variation of a measured fraction or the WLR is observed, then there may be a high probability that there is a deposition within The pipe.
Therefore, if the variation of the gas fraction is small compared to the variations of the oil and water fractions or if no gas is present in the fluid, if the differential pressure or the flow velocity are almost stable, and If the WLR (or fraction of water in the fluid) varies linearly with time, then we can conclude that
a deposition has occurred in the pipeline. As will be understood by those skilled in the art, the deposit may be of any material, such as wax, asphaltene, or scale, because no assumption has been made regarding the type of deposit.
In methods for detecting the presence of a reservoir in a pipeline according to the embodiments of the present disclosure, a first step may be to measure the NLR. { t) using any appropriate sampling technique in the art. For example, one technique is to radiate beams of photons with at least two energy levels through the multiphase fluid, where the photon beam is usually generated by a source of gamma and / or X rays. The deposit in the tubular structure is It can be understood as a thin layer that increases the thickness of the wall of the tubular structure.
If gamma rays are used, an additional layer formed by the deposit, as observed within a short relative time interval, on the wall of the tubular structure can cause an attenuation of the gamma radiation in addition to the attenuation caused by the fluid that flows in the tubular structure. This behavior can be treated as an artificial aging of the source of nuclear radiation. As is evident from equations (11) - (20), it can be justified to consider that the contribution of the fraction
from the gas of the fluid to the fluctuation of the WLR due to a deposit is small in comparison to the contributions of the oil and water fractions. The contribution of the gas to the WLR was therefore mathematically approximated by a linear compensation to the counting speeds measured in the fluid. Therefore, by using the methods according to the modalities described herein, it is not only possible to correct the fraction of the gas in the measurements of the fractions, but also to correct the decreased counting speed due to the deposit. Accordingly, during a measurement of the counting speed, the counting speed for an empty tubular structure can be artificially increased.
Example 1
Now a first method for measuring the thickness of a deposit will be described. Referring to Figures 2a and 2b, an empty pipe 101 is shown with a measuring device including a radiation source 103 and a radiation detector 105, where in Figure 2a no deposit is present in the pipe, and in the Figure 2b the tank 109 is present in the wall of the pipe 101. The scenario of Figure 2b can be achieved by closing the well (i.e., stopping the flow), and depressurizing the measuring device. The tank 109 shown has a thickness of ½ du.
With an empty pipe, the ratio of the counting speeds N0 (x) and Ni (x) without and 'with deposit, respectively, can be written as
where d is the distance between the radiation source 103 and the detector 105, dj = ¾d, and j = g, w, o, u. The counting speeds N0. { x) and Nz (x) without and with deposit, respectively, differ from each other by? (?),
(22)
which can be considered as the artificial aging of the source 103 of radiation. Due to the temporal linearity of the deposition velocity described above, we can assume then that during a time interval At = t2 - ti which is sufficiently short (ie, e «1), the source 103 is" aged "by ?? . { ?) Consequently, the term ?? (?) Can be determined by measuring the counting speed in the empty pipe at two different times ti and t2 (before deposition occurs and once the deposit is present). It is then possible to calculate N { x, t)
AN (x)
N (x, t) = N0 (x) +
M (23)
with N (x, t) the empty pipe count rate being re-calculated in any period of time t based on two consecutive measurements made of the empty pipe. Through expression (23), it may be possible to construct a relation for a deposition rate that varies linearly with time. It may also be possible to obtain the counting speed of the empty pipe if no deposition occurs (No (x)) ·
The total thickness of the deposition in the tubular structure that is traversed by the radiation can then be approximated by the following expression:
It should be noted that in this modality, the type of deposition must be known in order to determine the density and the mass attenuation coefficient of the deposit component.
As will be appreciated by those skilled in the art, the measurements in this example can also be carried out in a tubular structure that is filled with a known fluid after the flow of the well fluid has stopped. This modality can also be applied if the tubular structure, in which the counting speed measurements are carried out, includes a deviation that allows not
stop the flow in the system.
Example 2
In another example, the fluid flow may not have to be stopped. First, the presence of a deposit can be detected by observing the temporal evolution of the WLR. Subsequently, the WLR can be measured before and after detection of the deposit in two energy levels Ex and Ey. The WLR of the fluid must be the same before and after the deposition has occurred. The ratio of the counting speed with deposit to the counting speed of the empty pipe without deposit, ln [Ni (x) / N0 (x)], is then readjusted until the WLR measured after the deposit detection is the same as without the deposit in the tubular structure (that is, until the fractions of oil and water are the same before and after the detection of the deposit).
An estimate based on an inverted model can then be used to calculate the expected counting speed of the empty pipe for each energy, ie, N0 (x) becomes
where the fractions a ± are those calculated from the measurements without deposit. The same applies for A¾ (y).
The following two systems of equations (before and after deposition) can then be used to calculate the oil and water fractions using an iterative method to obtain the same WLR in both cases:
to. = 1
, = 1.
N0 (x) is the empty pipe count rate before a deposition occurs, and N¡ (x) is the empty pipe count rate after a deposition has occurred. In addition, from the systems (26) and (27), the following expression can be derived:
(28)
where vu are the mass attenuation coefficients of the
reservoir material for the radiation energies Ex and Ey.
In the readjustment of the proportion of counting speeds
in (28), the attenuation vu coefficients of a material of the
reservoir for the two radiation energies Ex and Ey can be
find using a database (look-up table) that
list the attenuation coefficients for these energies for
Various kinds of deposit. For the illustration, table 1
list the mass attenuation coefficients for materials
typical in 32 keV and 81 keV. The database needs
implemented with the system.
Table 1: Mass attenuation coefficients for 32 keV and 81 keV for various materials.
Once a deposit material has been found that
better match equation (28), you can know the
density of the deposit material. Using then the
Equation (21), you can get an estimate of the distance
total du crossed by the radiation inside the deposit, to
Through the relationship:
where we assume that the thickness < ¾ß? of the deposit is uniform around the circumference of the tubular structure so that the radiation passes twice as it propagates through the tubular structure. Advantageously, this second example only requires that a database listing the attenuation coefficients for the X-ray and / or gamma energies used for the measurements be present within the system. No further knowledge of the type of deposition is required.
Example 3
In a third embodiment, two different radiation energies are also used for the counting speed measurements. Here, it can be assumed that the mass attenuation coefficient of the reservoir for the highest energy can be adjusted by a polynomial function of the mass attenuation coefficient of the reservoir at the lowest energy. This assumption is true for most deposit materials, except, among others, for BaS04. For example, in the case of Barium, the polynomial function can be written as
v (y) = h v * (x) + kv (x) + I (30) where h, k, and 1 are integers, Ey - 81 keV, and Ex = 32 keV. The relation (30) is represented in the graph shown in Figure 3.
To identify the deposit material, the mass attenuation coefficient v (x) can be calculated by combining equations (28) and (30),
= av (x) + b v (x) + c (31)
The thickness of the deposit can then be found by following the method detailed in the second example. In this modality, v (x) and v (y) can be measured and not extrapolated from a database. The density of the deposit can be found using a look-up table with densities at different radiation energies.
Those skilled in the art will appreciate that, in the
Examples 2 and 3 described above, more than three radiation energies can be used.
Example 4
In a fourth embodiment, the measurements of the
Counting speed can be carried out using three different levels of radiation energy EX I Ey, and Ez. The three radiation energies can be provided by combining, for example, several radioactive sources or a radioactive source and an X-ray source.
To obtain the mass attenuation coefficient of the deposit material, you can use systems of equations similar to (26) and (27) (for the case of two energies in Example 2), where each system of equations contains three relationships for the rates of counting speed. From these, two coupled equations can be derived for the mass attenuation ratios:
As in Example 2 described above, the proportions (32) can be readjusted to determine the deposit material using a database as in table 2 which lists the attenuation coefficients for different materials and the radiation energies. The relationship between the two proportions of the attenuation coefficients in equations (32) (low / high energy versus energy
low / medium) is represented in the graph shown in the Figure
4 for Barium with Ex = 32 keV, Ey = 81 keV, and Ez = 356 keV.
Table 2: Mass attenuation coefficients for 32 keV, 81 keV, and 356 keV for various materials.
However, at high radiation energies, for example
356 keV, absorption of radiation can become
dependent on the density of the deposit. The density
electronics pB ± of the deposit material can be associated with the
proportion of counting speeds with and without deposit by the following relationship:
where K is a constant that depends essentially on the
geometry of the system. The density of mass can be obtained
then through
where Z is the atomic number and A is the mass number of the material. For most deposit materials, with the exception of CH4, we can estimate 2 x Z / A ¾ 1.
To calculate the mass attenuation coefficients of the reservoir material, the density of the reservoir material can first be estimated using the ratio (33) of high energy count rate and then equation (34). Subsequently, using one of the methods described in Examples 2 or 3, a set of solutions can be obtained
From these, the thickness can be calculated similarly to the method in the second example. Those skilled in the art will appreciate that more than three radiation energies can be used.
In this modality, due to the use of a third radiation energy, an additional characteristic can be obtained
of the deposit from the measurements of the counting speed. The additional feature may be, for example, the density of the deposit. Using this information with the associated proportion of the mass attenuation coefficients as expressed in (36), fewer assumptions about the deposit type may be needed, and better discrimination of the composition of the deposit can be obtained.
If the methodology proposed in Example 3 is used (for example, equation (31)), the deposit can be fully described with (pei, vu (x), vu (y)). In this case, if we apply equation (29) then, it may still be possible to describe the deposit (the mass attenuation coefficient, the density) without any additional knowledge (ie, no attenuation database has to be present) of dough) . It may then be possible to directly calculate the thickness of the deposit.
Those skilled in the art will appreciate that in each of the examples, once the mass attenuation coefficient and the density of the deposit have been determined, the coefficient ß of linear attenuation can easily be obtained through the ratio ß = vp In this way, the methods according to the modality described in the fourth example allow to obtain any combination of characteristics of the deposit (for example, the coefficient of
linear attenuation, mass attenuation coefficient, density, thickness). The modalities described here can cover any type of output combination. { pei, pu, vu (x), vu (y)).
Having access to the thickness of the deposit, it may be possible to consider the deposition rate. This can be done by several measurements of the counting speed in at least two different times separated by varying time intervals. This stage will allow the operator to know when a tubular structure should be "scraped" if the restriction due to the deposit becomes too large. It can also allow the monitoring of the effectiveness of a chemical injected into the pipe to dissolve the deposition. In this way, since the well maintenance program can be optimized, production postponement can be avoided.
In a second aspect, the embodiments described herein relate to the apparatus for detecting deposits in the tubular structures. The apparatus is partially depicted in Figures 1 and 2, where the apparatus includes a radiation source 103 for radiating a beam of photons through the fluid and a radiation detector 105 for measuring the absorption of radiation in the fluid to obtain the absorption data. The radiation source 103 can be any source of
suitable radiation known in the art, such as, but not limited to, X-ray or gamma-ray sources or combined X-ray / gamma sources. Similarly, the detector 105 may be any suitable detector known in the art, such as, but not limited to, scintillation counters or Geiger. The apparatus may further include processors for carrying out the methods according to the embodiments described herein, and output units for outputting the deposit information for a user.
The deposition of incrustations with a thickness of less than 0.3 mm has been detected with the methods according to the modalities described herein. In addition, the incrustation has been identified without any problem. Those skilled in the art will appreciate that the methods are applicable to any other kind of deposit.
The methods according to the modalities described herein can also be applied to any system in which it is necessary to monitor a deposition, wherein the deposit can be composed of any material, having any concentration. For example, the methods to identify and characterize deposits are applicable in the food industry as well as in the oilfield.
While the disclosure has been described with respect to
a limited number of modalities, those skilled in the art, who have the benefit of this disclosure, will appreciate that other modalities can be devised that do not deviate from the scope of the invention as described herein. Accordingly, the scope of the invention should be limited only by the appended claims.
Claims (21)
1. A method for detecting deposits in a tubular structure in which a fluid flows, the method characterized in that it comprises: measure the water-liquid ratio of the fluid as a function of time; Y determine that a deposit exists if the measured water-liquid ratio of the fluid as a function of time is linear.
2. The method of claim 1, characterized in that the measurement of the water-liquid ratio comprises: radiate a beam of photons of at least two energy levels through the fluid.
3. The method of claim 1, characterized in that it further comprises determining the thickness of the deposit if a deposit is detected.
4. The method of claim 3, characterized in that it further comprises: stop the flow of fluid; radiate a beam of photons of a first energy level through the tubular structure filled with a known fluid; measuring an absorption of the radiation in the tank to obtain the absorption data of the tank in the first and second time intervals; comparing the absorption data of the deposit with the predetermined absorption data of the empty tubular structure without deposit to obtain a difference of the absorption data of the deposit and the predetermined absorption data; Y calculate the thickness of the deposit using the difference of the absorption data of the deposit and the predetermined absorption data, the density of the deposit, and the mass attenuation coefficient of the deposit.
5. The method of claim 1, characterized in that it further comprises identifying the deposit if a deposit is detected.
6. The method of claim 5, characterized in that it further comprises: radiate beams of photons of two energy levels through the tubular structure; measure the absorption of radiation in the reservoir to obtain the absorption data of the reservoir at each energy level; use an iterative method to determine the corrected absorption data using the no-deposit absorption data to obtain the same water-liquid ratio with deposit and without deposit; Y readjust the proportions of the absorption data corrected to the no-deposit absorption data at each energy level to obtain a proportion of the mass attenuation coefficients at the two energy levels using a database of materials from the deposit. .
7. The method of claim 6, characterized in that it further comprises determining the thickness of the deposit using the ratio of the corrected absorption data and the absorption data without deposit, the density of the deposit, and the mass attenuation coefficient of the deposit preliminarily identified .
8. The method of claim 5, characterized in that it further comprises: radiate beams of photons of two energy levels through the tubular structure; measure the absorption of radiation in the tank to obtain the absorption data of the tank; Y determine the mass attenuation coefficient of the deposit using a polynomial adjustment between the mass attenuation coefficients of the two energy levels.
9. The method of claim 8, characterized in that it further comprises determining the thickness of the deposit using a ratio of absorption data corrected to absorption data without deposit, a density of the deposit, and a Mass attenuation coefficient of the deposit previously identified.
10. The method of claim 5, characterized in that it further comprises: radiate beams of photons of three energy levels through the tubular structure; measure the absorption of radiation in the reservoir to obtain the absorption data of the reservoir at each energy level; use an iterative method to determine the corrected absorption data using the no-deposit absorption data to obtain the same water-liquid ratio with deposit and without deposit; Y adjust the proportions of the corrected absorption data to the no-deposit absorption data at each energy level to obtain two proportions of the mass attenuation coefficients at the three energy levels using a database of deposit materials.
11. The method of claim 10, characterized in that it further comprises determining the thickness of the deposit using the ratio of the corrected absorption data and the absorption data without deposit, the density of the deposit, and the mass attenuation coefficient of the deposit preliminarily identified .
12. The method of claim 5, characterized in that it further comprises: radiate beams of photons of three energy levels through the tubular structure; measure the absorption of radiation in the tank to obtain the absorption data of the tank; determine the electron density of the reservoir using a proportion of the corrected absorption data and the no-deposit absorption data at the highest of the three energy levels.
13. The method of claim 12, characterized in that it further comprises determining the density of the deposit.
14. The method of claim 13, further comprising determining the mass attenuation coefficients of the deposit, characterized in that it comprises: use an iterative method to determine the corrected absorption data using the non-deposit absorption data in order to obtain the same water-liquid ratio with deposit and without deposit; Y adjust the proportions of the corrected absorption data to the no-deposit absorption data at each energy level to obtain a proportion of the mass attenuation coefficients at the three energy levels using a database of deposit materials.
15. The method of claim 14, characterized in that it further comprises determining the thickness of the deposit using the ratio of the corrected absorption data and the absorption data without deposit, the density of the deposit, and the mass attenuation coefficient of the deposit preliminarily identified .
16. The method of claim 12, characterized in that it further comprises determining a mass attenuation coefficient of the reservoir using a polynomial adjustment between the mass attenuation coefficients of the three energy levels.
17. The method of claim 16, characterized in that it further comprises determining a deposit thickness using a ratio of the corrected absorption data and the non-deposit absorption data, a deposit density, and the mass attenuation coefficient of the deposit preliminarily identified .
18. An apparatus for detecting a reservoir in a tubular structure in which a fluid flows, the apparatus characterized in that it comprises: a measuring device configured to measure a water-liquid ratio of the fluid as a function of time; Y a processor configured to determine that there is a deposit if the water-liquid ratio as a function of time is linear.
19. The apparatus of claim 18, characterized in that the measuring device comprises: a radiation source for radiating photon beams of at least two energy levels through the fluid.
20. The apparatus of claim 19, characterized in that the radiation source comprises at least one of a source of gamma rays and an X-ray source.
21. The apparatus of claim 16, characterized in that it further comprises: a radiation source to radiate a beam of photons at an energy level; a radiation detector to measure the absorption of the photon beam radiation; wherein the processor is configured to determine at least one of a deposit thickness, a mass attenuation coefficient, and a deposit composition.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US2437008P | 2008-01-29 | 2008-01-29 | |
| PCT/IB2009/050365 WO2009095876A2 (en) | 2008-01-29 | 2009-01-29 | Detection and automatic correction for deposition in a tubular using multi-energy gamma-ray measurements |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| MX2010008132A true MX2010008132A (en) | 2010-11-12 |
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Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| MX2010008132A MX2010008132A (en) | 2008-01-29 | 2009-01-29 | Detection and automatic correction for deposition in a tubular using multi-energy gamma-ray measurements. |
Country Status (3)
| Country | Link |
|---|---|
| CA (1) | CA2725061C (en) |
| MX (1) | MX2010008132A (en) |
| WO (1) | WO2009095876A2 (en) |
Families Citing this family (4)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| EP2431716A1 (en) * | 2010-06-30 | 2012-03-21 | Services Petroliers Schlumberger | A multiphase flowmeter and a correction method for such a multiphase flowmeter |
| EP2671623A1 (en) * | 2012-06-08 | 2013-12-11 | Services Petroliers Schlumberger (SPS) | Method and arrangement for preventing hydrocarbon based deposition |
| WO2016064834A2 (en) * | 2014-10-22 | 2016-04-28 | Shell Oil Company | Improved methods of detecting flow line deposits using gamma ray densitometry |
| CN116592774B (en) * | 2023-07-18 | 2023-09-19 | 成都洋湃科技有限公司 | Pipe wall dirt detection method and device, storage medium and electronic equipment |
Family Cites Families (4)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CA1257712A (en) * | 1985-11-27 | 1989-07-18 | Toshimasa Tomoda | Metering choke |
| US6097786A (en) * | 1998-05-18 | 2000-08-01 | Schlumberger Technology Corporation | Method and apparatus for measuring multiphase flows |
| AU7751300A (en) * | 1999-10-04 | 2001-05-10 | Daniel Industries, Inc. | Apparatus and method for determining oil well effluent characteristics for inhomogeneous flow conditions |
| US20070189452A1 (en) * | 2006-02-16 | 2007-08-16 | Bp Corporation North America Inc. | On-Line Tool For Detection Of Solids And Water In Petroleum Pipelines |
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2009
- 2009-01-29 WO PCT/IB2009/050365 patent/WO2009095876A2/en active Application Filing
- 2009-01-29 CA CA2725061A patent/CA2725061C/en not_active Expired - Fee Related
- 2009-01-29 MX MX2010008132A patent/MX2010008132A/en active IP Right Grant
Also Published As
| Publication number | Publication date |
|---|---|
| CA2725061A1 (en) | 2009-08-06 |
| CA2725061C (en) | 2017-08-22 |
| WO2009095876A2 (en) | 2009-08-06 |
| WO2009095876A3 (en) | 2009-12-30 |
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